The invention relates generally to combustion gas turbines and more specifically to system control for blending secondary gases with a primary gas fuel and operating the gas turbine with the blended fuel mixture.
Heavy-duty gas turbines equipped with Dry Low NOx (DLN) combustion system have typically operated on 100% pipeline natural gas fuel. In recent years, natural gas fuel prices have continued to increase dramatically, forcing combustion turbine power plants to explore alternates to natural gas fuels. Many power plants are evaluating use of alternate fuels such as imported liquefied natural gas (LNG) as several terminals are being permitted in the US and other parts of the world for LNG introduction. Certain industrial and petrochemical businesses that employ combustion gas turbines also produce hydrogen-containing process gases (also known as off-gas) during chemical processes as a by-product. These process gases often times possess substantial heating value. Process gases contain hydrogen, as well as hydrocarbon species such as methane, ethane, etc. Such businesses desire to reduce natural gas fuel consumption for their combustion gas turbines by blending some percentage of process off-gases with their main natural gas fuel supply. In other instances, non-fuel gases may be added to the fuel-air mixtures to enhance power output from the gas turbine.
Gas turbines equipped with low Nitrous xide (NOx) emission combustion systems typically employ a process known as lean, pre-mixed combustion where fuel and combustion air are mixed upstream of the combustion zone to control and limit thermal NOx production. Such combustion systems often function well over a relatively narrow range of fuel injector pressure ratios and fuel compositions. If gas turbine combustion systems are operated outside of that range, combustion dynamics levels (noise pressure waves due to oscillatory combustion process) can get large enough to cause significant distress to combustion parts, thereby shortening the maintenance intervals or even cause irreparable hardware damage and forced outages. Historically, pipeline natural gas composition in general and specifically it's Wobbe Index (WI) and Modified Wobbe Index (MWI) have varied very slightly. MWI is calculated using an equation MWI=[LHV/sqrt(SG*T)], where LHV represents fuel Lower Heating Value (BTU/SCFT), SG represents specific gravity of fuel gas relative to air and T represents gas fuel temperature in degrees Rankine (also known as degrees absolute). Combustion turbine fuel nozzles are sized for a limited range of natural gas fuel MWI variations and a permissible variation in MWI of ±5% is generally accepted in gas turbine industry.
For many low NOx combustion systems, often times periodic adjustments to fuel schedules are required for maintaining acceptable levels of dynamics when the MWI of incoming gas fuel varies either due to changes in fuel temperatures or fuel compositional changes which impacts Lower Heating Value (LHV). Such fuel schedule adjustments (also referred to as “re-tuning”) are expensive requiring trained specialists from original equipment manufacturer (OEM) and instrumentation.
Consequently, turbine equipment suppliers typically tightly control the content of fuels for their DLN (Dry Low NOx) gas turbines. As a result, fuel specifications do not typically allow any amount of hydrogen to be present in the fuel gas of lean pre-mixed combustion systems due to the increased risk introduced by the hydrogen.
U.S. Pat. No. 6,082,092 by Vandervort teaches that by monitoring of gas Modified Wobbe Index (MWI), the pre-heat temperature of the fuel can be adjusted up or down to maintain the gas fuel MWI within the relatively narrow range required for the combustion system.
Attempts have also been made in various disparate applications to utilize mixture of natural gas fuel with other gas fuels as a blended fuel. U.S. Pat. No. 6,874,323 invented by Stuttaford describes a method of operating a gas turbine with a specific combustor structure to achieve overall lower emissions of nitrous oxides by supplying a mixture of natural gas and hydrogen gas to the combustion chamber of the gas turbine in a manner that the localized concentration of hydrogen gas is greater than 0.1% by mass of the mass of the mixture, and less than 20% by mass of the mixture prior to the combusting the mixture in the combustion chamber. U.S. Pat. No. 6,282,883 invented by Uematsu et. al. illustrates an easy plant starting provided in a hydrogen burning turbine plant for burning hydrogen and oxygen to generate high temperature steam for driving a turbine. U.S. Pat. No. 6,890,671 invented by Roche et. al. relates to fuel cell power plants, and more particularly operation of fuel cell power plants from multiple fuel sources. Fuel mixing control arrangements are provided for a fuel cell power plant operating on multiple fuels.
However, none of the above-described prior art provides a system for blending secondary gases or gas fuels with a primary gas fuel in a DLN gas turbine combustor premixing the fuel blend in all combustor nozzles and combusting within a single downstream combustion zone. Also the prior art does not control the fuel blend to avoid combustion dynamics and maintain low turbine exhaust emissions. Further with respect to blending of fuels, the addition of non-fuel, alternate gases such as nitrogen and carbon dioxide to a primary gas fuel has not been described in such applications.
Accordingly, there is a need to provide a system allowing combustion turbine power plant owners to simultaneously reduce natural gas fuel consumption, reduce green house gas emissions, reduce operating costs and increase fuel flexibility. The system must control and modulate amount of alternate gas or alternate fuel (such as hydrogen, propane, butane, LNG etc.) injected into the primary gas fuel system of a combustion turbine equipped with low NOx emission combustion controls such that blended fuel gas properties are within acceptable range for combustion fuel nozzle designs.